NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency & 

Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Western Wind and Solar 

Integration Study Phase 3 – 

Frequency Response and 

Transient Stability: 

Executive Summary

N.W. Miller, M. Shao, S. Pajic, and R. D’Aquila

GE Energy Management

Schenectady, New York

NREL Technical Monitor: Kara Clark

Link to full report

Subcontract Report

NREL/SR-5D00-62906-ES

December 2014
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy 

Laboratory

15013 Denver West Parkway

Golden, Colorado 80401

303-275-3000 • www.nrel.gov Contract No. DE-AC36-08GO28308

Western Wind and Solar 

Integration Study Phase 3 –

Frequency Response and 

Transient Stability: 

Executive Summary

N.W. Miller, M. Shao, S. Pajic, and R. D’Aquila

GE Energy Management

Schenectady, New York

NREL Technical Monitor: Kara Clark

Prepared under Subcontract No. DRS8.3020

Subcontract Report

NREL/SR-5D00-62906-ES

December 2014
 

NOTICE

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Cover Photos: (left to right) photo by Pat Corkery, NREL 16416, photo from SunEdison, NREL 17423, photo by Pat Corkery, NREL 

16560, photo by Dennis Schroeder, NREL 17613, photo by Dean Armstrong, NREL 17436, photo by Pat Corkery, NREL 17721.

NREL prints on paper that contains recycled content.
iv

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Acknowledgments

The National Renewable Energy Laboratory (NREL) and GE gratefully acknowledge the support 

of Charlton Clark (Wind and Water Power Program) and Venkat Banunarayanan (SunShot 

Initiative) from the U.S. Department of Energy (DOE) Office of Energy Efficiency and 

Renewable Energy for funding this work.

NREL and GE also thank the members of the Technical Review Committee (TRC) for their 

insightful comments and assistance. Participation in the TRC does not imply agreement with the 

project findings. The TRC included:

• Eric Allen, North American Electric Reliability Corporation (NERC)

• Jamie Austin, PacifiCorp

• Sam Baldwin, DOE

• Venkat Banunarayanan, DOE

• Ben Brownlee, Western Electricity Coordinating Council (WECC)

• Neil Burbure, NERC

• Ray Byrne, Sandia National Laboratories

• Tom Carr, Western Governors' Association (WGA)

• Charlton Clark, DOE

• Bob Cummings, NERC

• Tom Duane, Public Service Company of New Mexico (PNM)

• Bob Easton, Western Area Power Administration (WAPA)

• Sara Eftekharnejad, Tucson Electric Power (TEP)

• Steve Ellenbecker, WGA

• Ryan Elliott, Sandia National Laboratories

• Abe Ellis, Sandia National Laboratories

• Joe Eto, Lawrence Berkeley National Laboratory (LBNL)

• Irina Green, California Independent System Operator (CAISO)

• Fred Huang, Electric Reliability Council of Texas (ERCOT)

• Dmitry Kosterev, Bonneville Power Administration (BPA)

• Doug Larson, WGA

• Debra Lew, Independent Consultant

• Yishan Li, WAPA

• Clyde Loutan, CAISO
v

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• Jim McCalley, Iowa State University 

• Jeff Mechenbier, PNM

• Mark O'Malley, University College Dublin

• Brian Parsons, Independent Consultant

• Pouyan Pourbeik, Electric Power Research Institute (EPRI)

• Jim Reilly, DOE

• Sandip Sharma, ERCOT

• Cesar Silva-Monroy, Sandia National Laboratories

• David Silver, Xcel Energy

• Charlie Smith, Utility Variable-Generation Integration Group (UVIG)

• Justin Thompson, Arizona Public Service (APS)

• John Undrill, Independent Consultant

• Vijay Vittal, Arizona State University

• Janice Zewe, Sacramento Municipal Utility District (SMUD)

NREL regrets any inadvertent omission of any project participants and contributors.
vi

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Abbreviations and Acronyms

AC alternating current

COI California-Oregon Interface

CSP concentrating solar thermal power

DC direct current

DG distributed generation, embedded PV

FR frequency response

FRO frequency response obligation

GR governor response

GW gigawatt

Hz Hertz

IFRO interconnection frequency response obligation

MVA megavolt ampere

MW megawatt

NERC North American Electric Reliability Corporation

PDCI Pacific DC Intertie

PV photovoltaic solar power, utility-scale photovoltaic power plant

RAS remedial action scheme

ROCOF rate of change of frequency

s second

UFLS under-frequency load shedding

WECC Western Electricity Coordinating Council

WWSIS Western Wind and Solar Integration Study
vii

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Table of Contents

List of Figures ........................................................................................................................................... vii

List of Tables ............................................................................................................................................. vii

Introduction ................................................................................................................................................. 1

Frequency Stability Background ............................................................................................................ 1

Transient Stability Background.............................................................................................................. 5

Study Scenarios...................................................................................................................................... 7

Frequency Response Results................................................................................................................ 12

Means to Improve Frequency Response............................................................................................... 17

Transient Stability Results.................................................................................................................... 20

Means to Improve Transient Stability .................................................................................................. 24

Model Improvement and Further Analysis........................................................................................... 25

Conclusions.......................................................................................................................................... 27

References................................................................................................................................................. 28

List of Figures

Figure 1. North American electricity grid interconnections. .................................................................. 2

Figure 2. Balance analogy for frequency stability................................................................................... 3

Figure 3. Electricity demand exceeds electricity generation, and frequency drops. .......................... 3

Figure 4. System frequency in response to a large generation trip. ..................................................... 4

Figure 5. Mechanical analogy for transient stability (Vittal 2003).......................................................... 6

Figure 6. Substation voltage in response to transmission system disturbance.................................. 6

Figure 7. Wind and solar generation in the Light Spring Base case. .................................................... 9

Figure 8. Wind and solar generation in the Light Spring Hi-Mix case................................................. 10

Figure 9. Wind and solar generation in the Light Spring Extreme case. ............................................ 10

Figure 10. Wind and solar generation in the Heavy Summer Base case. ........................................... 11

Figure 11. Wind and solar generation in the Heavy Summer Hi-Mix case.......................................... 11

Figure 12. Frequency response to loss of two Palo Verde units under light spring system 

conditions............................................................................................................................................ 13

Figure 13. Frequency response of Light Spring Hi-Mix case – DG trip vs. two Palo Verde unit trip.16

Figure 14. Frequency response to two Palo Verde unit trip for Light Spring Hi-Mix case with three 

combinations of frequency controls on wind plants...................................................................... 18

Figure 15. Frequency response to two Palo Verde unit trip for Light Spring Hi-Mix – with and 

without governor control on utility-scale PV plants. ...................................................................... 19

Figure 16. Frequency response to two Palo Verde unit trip for Light Spring Hi-Mix – with and 

without energy storage...................................................................................................................... 20

Figure 17. COI Flows for PDCI event for Heavy Summer cases........................................................... 21

Figure 18. Coal displacement in Desert Southwest and Northeast regions for Light Spring cases.23

Figure 19. Dave Johnson bus voltage for Aeolus fault – Light Spring Base vs. Hi-Mix vs. Extreme 

vs. Extreme with synchronous condenser conversion.................................................................. 23

Figure 20. Malin station bus voltage in response to PDCI event – with and without CSP governor 

control.................................................................................................................................................. 24

Figure 21. Load-induced voltage collapse in Heavy Summer Base case. .......................................... 25

List of Tables

Table 1. Renewable Generation Summary for All Study Scenarios .................................................... 12

Table 2. Summary of Frequency Response ........................................................................................... 14

Table 3. Summary of Frequency Nadir and Settling Frequency for Light Spring Cases .................. 15
1

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Introduction

All of the large-scale regional wind and solar integration studies performed by the National 

Renewable Energy Laboratory (NREL) and others have identified the lack of power system 

dynamic analysis as a significant research gap. Acceptable dynamic performance of the grid in 

the fractions of a second to one minute following a large disturbance (e.g., loss of a large power 

plant or a major transmission line) is critical to system reliability, thus there is a need to analyze 

the dynamic behavior of North American systems under high variable renewable conditions. The 

Western Interconnection, in particular, has a long history of dynamic performance constraints on 

system operation—so any dynamic performance changes due to increased wind and solar 

generation could have substantial impact on all aspects of renewable integration. The primary 

objectives of Phase 3 of the Western Wind and Solar Integration Study (WWSIS-3) are to 

examine the large-scale transient stability and frequency response of the Western Interconnection 

with high wind and solar penetration, and to identify means to mitigate any adverse performance 

impacts via transmission reinforcements, storage, advanced control capabilities, or other 

alternatives.

WWSIS-3 evaluated a variety of system conditions, disturbances, locations, and renewable 

penetration levels to help draw broader conclusions from an analysis of two specific types of 

power system stability: frequency stability and transient stability. A technical definition of the 

different aspects of power system stability is provided in (Kundur et al. 2004). Less technical 

descriptions of both frequency and transient stability are provided in the following sections of 

this report.

Frequency Stability Background 

To reliably operate a large, interconnected power grid such as the Western Interconnection 

(shown in Figure 1) requires a constant balancing of electricity generation with electricity 

demand. Electricity must be generated at the same instant it is used, so operating procedures 

have developed to forecast electricity demand, schedule electric generators to meet that demand, 

and ensure sufficient generating reserves are available to respond to forecast errors and system 

disturbances. The measure of success in this balancing act is frequency. In North America, that 

means maintaining system frequency at or very close to 60 Hz, as shown in Figure 2.

However, disturbances do occur, including large ones that affect overall system frequency (e.g., 

abrupt outage of a large generator or a major transmission line). For example, a transmission line 

outage may disconnect a large industrial customer, and as a result, the total electricity generation 

exceeds the total electricity demand, and frequency rises. Because operators, in general, have 

more control over generation than demand, they can execute a generation reduction to regain the 

balance and return system frequency to near 60 Hz. 

A potentially more significant problem is the loss of a large generating plant. As a result of this 

type of disturbance, the total electricity demand exceeds the total electricity generated and 

frequency drops, as shown in Figure 3. In general, a power grid is designed to withstand the loss 

of the single largest generator. However, the loss of multiple generators or plants may cause the 

frequency to drop significantly such that protective devices act to disconnect customers in order 

to preserve the bulk of the system. It is a serious reliability failure when operators lose the ability 

to supply all the electricity needed to meet demand. 
2

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Figure 1. North American electricity grid interconnections.

1

 1 http://www.nerc.com/AboutNERC/keyplayers/Documents/NERC_Interconnections_Color_072512.jpg
3

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Figure 2. Balance analogy for frequency stability.

Figure 3. Electricity demand exceeds electricity generation, and frequency drops.

Electricity

Generation

Electricity

Demand

Frequency

60 Hz

59.5 Hz 60.5 Hz

Electricity

Generation

Electricity

Demand

Frequency

60 Hz

59.5 Hz 60.5 Hz
4

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An example of system frequency in response to a large generation trip is shown in Figure 4. The 

system is operating normally, with a frequency of 60 Hz, up to 1 second. At that time, a large 

generating unit is abruptly lost. Load now exceeds generation, so the frequency drops. The speed 

of the initial decline is related to the number of conventional synchronous generators on the 

system. More generators mean more inertia, which retards the frequency decline. At about 10 

seconds, the frequency nadir or minimum is reached. Frequency nadir is one measure of a 

system's frequency stability—it must be above the highest level of under-frequency load 

shedding. At that point in time, the generators with governor controls have begun to act to 

increase power output, and thus the system frequency begins to recover. By about 60 seconds, 

the system frequency has settled out somewhat below the normal operating frequency of 60 Hz. 

Another metric of frequency stability is based on the change in frequency between the nadir and 

this settling frequency, and the change in power between these two points in time. This is called 

frequency response (FR) and is formally defined by the North American Electric Reliability 

Corporation or NERC (NERC 2012). After 60 seconds, even more generators begin to increase 

their power output, and the frequency returns to normal within about 10 minutes. One part of 

WWSIS-3 focuses on system frequency behavior in the first 60 seconds following an outage.

Figure 4. System frequency in response to a large generation trip.

59.6

59.7

59.8

59.9

60

60.1

0 10 20 30 40 50 60

Frequency (Hz)

Time (Seconds)

Frequency

Minimum or Nadir

Settling 

Frequency
5

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There is general concern among power system operators and utilities regarding the degradation 

of FR in North America over the past two decades. The decline is due to various factors,

including the withdrawal of primary or governor response (GR) shortly after an event, the lack of 

in-service governors on conventional generation, and the unknown and changing nature of load 

frequency characteristics. Large penetrations of inverter-based, or non-synchronous, generation 

technologies further complicate this issue. Without special operation or controls, wind and solar 

plants do not inherently participate in the regulation of grid frequency. By contrast, synchronous 

machines always contribute to system inertia, and some fraction of the synchronous generation in 

operation at any point has governor controls enabled. When wind and solar generation displaces 

conventional synchronous generation, the mix of the remaining synchronous generators changes 

and has the potential to adversely impact overall FR.

Therefore, one of the primary objectives of WWSIS-3 is to evaluate and to better understand the 

impact of high penetrations of wind and solar power on system-wide FR to large generator 

outages in the first minute after the outage occurs. 

Transient Stability Background 

In addition to maintaining the balance between electricity generation and electricity demand, 

power system operators must ensure that the grid can successfully transition from normal 

operation (e.g., all transmission lines and generating units are in service), through a disturbance 

(e.g., abrupt outage of a major transmission line or large generator), and into a new stable 

operating condition in the 10–20 seconds immediately following a disturbance. The ability to 

make this successful transition is called transient stability, and is an even faster phenomenon 

than frequency stability. 

A mechanical analogy for transient stability is illustrated by Figure 5 (Vittal 2003). Imagine a set 

of balls of different sizes connected to each other by a set of breakable elastic strings. The balls 

represent generators of different sizes and characteristics, and the strings represent the 

interconnecting transmission lines. The system is disturbed when one of the balls is hit with a 

stick. The ball begins to swing, and the string connected to the ball also swings. Other strings 

follow suit, and other balls start to swing. As a result of the single disturbance, the entire system 

of strings and balls is moving in response. If the swings die down, and the system comes back to 

rest, then the system is transiently stable. On the other hand, if the swings grow, one or more 

balls may break away from the rest, and the system is transiently unstable.
6

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Figure 5. Mechanical analogy for transient stability (Vittal 2003).

An example of both transient stability (blue) and transient instability (red) is shown in Figure 6. 

The system is operating normally, with a transmission substation voltage of 100%, up to 0.5 

seconds. At that time, a disturbance occurs, such as a tree falling on a transmission line. From 0.5 

seconds to 0.7 seconds, the voltage is zero because the tree is connecting the transmission line to 

the ground. At about 0.7 seconds, an automatic protection system trips the transmission line, and 

the voltage returns to near normal—but as described above, the system is swinging in response to 

the disturbance. When the swings grow and the system separates, the substation voltage drops 

precipitously, and the system collapses at about 1 second. When the swings die down, the 

substation voltage settles back to normal within 5 seconds. The second part of WWSIS-3 focuses 

on system stability in the first 5–10 seconds.

Figure 6. Substation voltage in response to transmission system disturbance.

0

20

40

60

80

100

120

140

0 1 2 3 4 5

Substation Voltage (%)

Time (Seconds)
7

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As noted, the Western Interconnection has a long history of constraints due to transient stability 

limitations that vary depending on system characteristics such as the level of electricity demand 

(e.g., peak summer load), the amount of power flowing on the transmission system (e.g., heavy 

flows on critical paths), and the location of generating plants in operation (e.g., remote from 

population centers). One of the primary objectives of WWSIS-3 is thus to evaluate and better 

understand the impact of high penetrations of wind and solar power on the large-scale transient 

stability of the Western Interconnection. The primary measures of transient stability are avoiding

bulk system separation and individual generator loss of synchronism with the system, and 

meeting various voltage and frequency swing criteria, which vary with the severity of the 

disturbance according to NERC and Western Electricity Coordinating Council (WECC) 

reliability standards.

While transient stability can be both systemic and local, this study focuses on large-scale events 

that affect the security of the entire interconnection. Large penetrations of inverter-based, or nonsynchronous, wind and solar generation may substantially alter system stability as a result of 

changes in angle/speed swing behavior due to reduced inertia, changes in voltage swing behavior 

due to different voltage control systems, different power flow patterns, and displacement of 

synchronous generation at key locations. 

Study Scenarios 

Transient stability and FR are dominated by the generation initial conditions. Thus, realistic and 

economically rational initial conditions are needed. The load flow that provides the starting point 

for dynamic simulations is a single snapshot in time and not, in itself, an economic tool. It is 

necessary to use economic tools to guide the commitment and dispatch process. Thus, the 

WWSIS-3 study scenarios leaned heavily on the work done for Phase 2 of the Western Wind and 

Solar Integration Study (WWSIS-2)—particularly the WWSIS-2 Hi-Mix scenario, which 

included 16.5% wind and 16.5% solar penetration on an annual energy basis. While the mapping 

between the WWSIS -2 system topology and the WWSIS-3 cases is good, it is not perfect. The 

studies used different analytical tools and different starting databases. 

In particular, the following data were derived from WWSIS-2 for WWSIS-3:

• Wind and solar plant capacity and location data

• Total power production of wind and solar plants by area

• Change in commitment and dispatch of conventional generation plants between the Base 

case (with low levels of renewable generation) and the Hi-Mix case.

Transmission system upgrades from WWSIS-2 were not used in the primary WWSIS-3 analysis, 

but a limited number were used for a sensitivity analysis.

Four primary study scenarios were developed to represent different system conditions (i.e., light 

and heavy load) and different renewable penetration levels (i.e., base and high renewables). The 

main focus of WWSIS-3 was to understand the impact of increasing renewable power levels, 

which made the starting cases critical. After extensive stakeholder input, two well-established 

future WECC planning cases were selected, representing light spring and heavy summer load 

conditions. These cases include transmission system upgrades that the WECC stakeholders 
8

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deemed likely within the next 10 years. However, no additional transmission system upgrades as 

identified by WWSIS II were used, except in the sensitivity analysis. Overall, this transmission 

system model gives a valuable reference, as both FR and transient stability concerns will tend to 

be improved by added transmission. If the system has acceptable dynamic performance, new 

transmission might still make economic sense, but it will not be needed to maintain stability and 

adequate FR even with high levels of wind and solar.

The study case development included improvements to the original WECC power flow and 

dynamic databases, as well as the addition of geographically appropriate wind and solar plants, a 

composite load model to allow for an appropriate representation of rooftop photovoltaics (PV), 

high renewable penetration levels (40–60 GW), and a detailed analysis of the WWSIS-2

production simulation results to determine de-commitment and re-dispatch procedures for the 

balance of the generation portfolio. 

The two light load scenarios include a Base case that represents a future in which the current 

renewable portfolio standard (RPS) targets are met. The Hi-Mix case was built from the Base

case, but with even higher levels of wind and solar. This case represents a snapshot in time—a

windy, sunny morning in the spring from the WWSIS-2 High Mix scenario (33% combined wind 

and solar by energy on an annual basis). The details (e.g., renewable plant MW output and siting, 

re-dispatch/de-commitment of the conventional units, etc.) were mined from the WWSIS-2

PLEXOS High Mix results. Great care was exercised to capture the economically rational change 

in commitment and dispatch that would accompany the wind and solar displacement of other 

generation. Limited local transmission reinforcements (e.g., synchronous condensers, shunt 

compensation) were added when the high renewables over-stressed local areas, but no major 

transmission projects were added beyond those built into the original WECC cases. A further 

sensitivity case, called Light Spring Extreme, was developed for additional analysis. This case

was based on the simultaneous extremes of the highest wind and solar generation, and a very low 

load level. An overview of the renewable generation for the light load scenarios is shown in

Figure 7 through Figure 9, and Table 1. The rooftop PV is shown in blue and is distinguished 

from utility-scale PV in yellow by the label “DG” (for distributed generation).

Similarly, there are two heavy summer scenarios—one base case and one high renewable case.

Again, the Heavy Summer Base case represents a future in which the RPS targets are met, but 

for a snapshot in time when the production of wind and solar is relatively low. The Heavy 

Summer Hi-Mix case was again mined from the PLEXOS High Mix results from WWSIS-2 and 

represents a high wind and solar condition that might occur during a summer high load day. As 

would be expected, the instantaneous production of wind, even with a similar installed fleet, is 

rather less than the spring case. An overview of the renewable generation for the heavy load 

scenarios is shown in Figure 10, Figure 11, and Table 1. The table shows power production 

levels for the snapshot in time represented by the cases, not the collective rating or capacity of 

the installed renewables. Similarly, the percent penetration is the instantaneous penetration, not 

an annual average.

For the dynamic simulations, all new wind plants were modeled as Type 3 doubly fed 

asynchronous machines with voltage regulation and low-voltage ride through (LVRT), all new 

concentrating solar power (CSP) plants were modeled as synchronous machines without GR, all 

new utility-scale PV plants were modeled as full converter asynchronous machines with voltage 
9

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regulation and LVRT, and all new distributed PV is modeled using the WECC composite load 

model.

The composite load model provides not only a means to model distributed PV—it allows for a 

more detailed model of the distribution system than is usual in a transmission-level study. In 

particular, this model also includes a substation transformer, distribution line, and four types of 

motor models, an electronic load, and a static load. This gives an overall load model for the 

Western Interconnection that has a higher proportion of motors than traditional studies, which 

will have a significant impact on the simulation results. Load modeling is a complex issue for 

both utility planners and researchers.

The primary tool in this work is GE’s PSLF software package—a commercial power flow and 

transient stability simulation tool.

Figure 7. Wind and solar generation in the Light Spring Base case.

Wind 4.4

PV 3.7

CSP 0.9

DG 0.0

Others 

19.9

Wind 

8.4 PV 0.0

CSP 0.0

DG 0.0

Others 

14.6

Wind 2.5

PV 0.0

CSP 0.0

Others DG 0.0

12.3

Wind 4.0 PV 0.2

CSP 0.0

DG 0.0

Others 24.9

Production/Dispatch in GW
10

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Figure 8. Wind and solar generation in the Light Spring Hi-Mix case.

Figure 9. Wind and solar generation in the Light Spring Extreme case.

Wind 4.7

PV 5.8

CSP 1.5

DG 3.7

Others 

15.1

Wind 

8.4

PV 0.3

CSP 0.0

DG 0.2

Others 

11.7

Wind 5.3

PV 0.8

DG 0.4 CSP 0.0

Others 

5.5

Wind 6.9

PV 3.3

DG 2.6 CSP 7.0

Others 11.4

Production/Dispatch in GW

Wind 4.5

PV 7.5

DG CSP 2.2

5.7

Others 

12.4

Wind 

8.3

PV 0.2

CSP 0.0

DG 0.1

Others 

9.3

Wind 7.0

PV 0.7

CSP 0.0

DG 0.7

Others 

4.1

Wind 10.9

PV 5.1

CSP

6.1

DG 3.8

Others 9.1

Production/Dispatch in GW
11

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Figure 10. Wind and solar generation in the Heavy Summer Base case.

Figure 11. Wind and solar generation in the Heavy Summer Hi-Mix case.

Wind 2.1

PV 1.1

CSP 0.4

DG 0.0

Others 

64.9

Wind 0.0

PV 0.0

CSP 0.0

DG 0.0

Others 

33.3

Wind 1.7 PV 0.0

CSP 0.0

DG 0.0 Others 

18.1

Wind 0.8 PV 0.1

CSP 0.0

DG 0.0

Others 

53.0

Production/Dispatch in GW

Wind 2.1

PV 5.8

CSP 3.1

DG 5.4

Others 

54.6

Wind 

6.9

PV 0.2

CSP 0.0

DG 0.3

Others 

29.8

Wind 

2.6 PV 1.3

CSP 0.0

DG 0.9

Others 

15.6

Wind 1.8 PV 3.8

CSP 3.5

DG 2.9

Others 

36.9

Production/Dispatch in GW
12

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Table 1. Renewable Generation Summary for All Study Scenarios

WECC-Wide 

Summary

Light 

Spring

Base

Light 

Spring

Hi-Mix

Light 

Spring

Extreme

Heavy 

Summer

Base

Heavy 

Summer

Hi-Mix

Wind (GW) 20.9 27.2 32.6 5.6 14.3

Utility-Scale PV 

(GW) 3.9 10.2 13.5 1.2 11.2

CSP (GW) 0.9 8.4 8.3 0.4 6.6

Distributed PV 

(GW) 0 7.0 10.4 0.0 9.4

Total = 25.7 52.8 64.8 7.2 41.5

Penetration(1) (%) = 21% 44% 53% 4% 20%

(1) Penetration is % of total generation.

Frequency Response Results

As previously described, FR is the overall response of the power system to large, sudden 

mismatches between generation and load. The primary concern is that the minimum frequency, 

or nadir, during design-basis disturbances should not cause under-frequency load shedding

(UFLS). In the West, the first stage of UFLS is normally at 59.5 Hz. The NERC standard also 

provides a specific definition of the quantitative metric “frequency response.” It is this metric 

that is compared to the frequency response obligation (FRO) to determine compliance.

This investigation focused on light spring conditions, as the relatively low level of generation 

may present a challenge for FR. Similarly, the analysis focused on the single largest design-basis 

generation outage in the Western Interconnection. According to BAL-003-1, this design-basis 

event is the trip of two fully loaded Palo Verde nuclear power station units for a loss of about 

2,750 MW. The subsequent frequency excursion is severe, as shown in Figure 12. This 

frequency is an MVA weighted average of all WECC synchronous machine speeds. The 

frequency nadir is 59.67 Hz in the base case (blue line), 59.65 Hz for the high renewable case 

(green line), and 59.61 Hz for the extremely high renewable case (red line). Thus, all cases avoid 

UFLS relay action, which begins at 59.5 Hz.
13 

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Figure 12. Frequency response to loss of two Palo Verde units under light spring system 

conditions. 

The Western Interconnection frequency response obligation (IFRO) will be updated annually, 

according to the NERC BAL-003-1 standard. The IFRO is given as 840 MW/0.1 Hz for this 

study. To help understand the system frequency performance, estimates of regional FROs were 

made. These estimated FROs are listed in the first column of Table 2. Actual FROs are assigned 

to individual balancing authorities (BAs) and are updated annually, so these estimated 

obligations are for reference only. They should not be used to determine individual BA 

compliance with the NERC standard. Table 2 is a summary of the FR for WECC, and four large 

U.S. regions, for all the key cases. 

The FR for cases plotted in Figure 3 are reported in their respective columns (Base, Hi-Mix and 

Extreme Hi-Mix). The WECC-wide FR meets its obligation in all cases, with some margin.

Portions of the system that rely primarily on thermal generation tend to be short of meeting their 

approximate FRO with their own generation resources, especially in the Hi-Mix case (e.g., the 

Desert Southwest and Northeast regions). This occurs because that thermal generation was 

displaced by wind and solar, which do not provide FR unless equipped with specific controls. 

Other regions, particularly the Northwest, far exceed their approximate FRO due to high levels 

of responsive hydropower. 

Light Spring Base

Light Spring Hi-Mix

Light Spring Extreme
14

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The other results shown in this table are from cases used to evaluate the impact of various means 

of improving FR. Three combinations of GE-standard frequency controls on wind plants were 

tested: governor control alone, inertial control alone, and the combination of the two. The inertial 

control alone has little impact on the FR metric compared to the Hi-Mix case. This control 

targets the first 10 seconds after a generation outage, while the FR metric is measured from 20

seconds to 52 seconds. One aggressive, non-standard control was used to test on the utility-scale 

PV. Note that the various combinations of frequency controls were only applied to the new wind 

plants and new utility-scale PV plants. In other words, only the wind and solar plants added to 

the Base case to create the Hi-Mix case, which are a subset of the total number of wind and solar 

plants, were used in these sensitivities. By contrast, the energy storage was sized specifically to 

provide the incremental FR needed for each area to meet its approximate FRO with its own 

resources. All the governor controls, regardless of technology, improved FR in the four regions. 

Table 2. Summary of Frequency Response

Light Spring Frequency Response (MW/0.1Hz)

FRO Base Hi-Mix Wind

Governor 

Control

Wind

Inertial 

Control

Wind

Governor 

and 

Inertial 

Controls

UtilityScale PV 

Governor 

Control

Energy 

Storage

with 

Governor 

Control

Extreme 

Hi-Mix

WECC 840 1,352 1,311 1,610 1,323 1,571 2,065 1,513 1,055

By Region

CALIFORNIA 296 305 312 335 315 334 562 369 295

DESERT 

SOUTHWEST 220 215 119 240 111 215 475 224 97

NORTHEAST 82 61 47 140 40 129 135 85 51

NORTHWEST 131 434 483 528 507 528 537 487 280

A summary of the frequency nadirs and settling frequencies for the Light Spring cases is shown 

in Table 3. All of the frequency-responsive control options improved both the frequency nadir 

and the settling frequency.
15

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Table 3. Summary of Frequency Nadir and Settling Frequency for Light Spring Cases

Light Spring WECC System Frequency Measures (Hz)

Base Hi-Mix Wind

Governor 

Control

Wind

Inertial 

Control

Wind

Governor 

and 

Inertial 

Controls

UtilityScale PV 

Governor 

Control

Energy 

Storage 

with 

Governor 

Control

Extreme 

Hi-Mix

Frequency 

Nadir 59.668 59.646 59.654 59.685 59.691 59.752 59.688 59.613

Settling 

Frequency 59.839 59.844 59.864 59.853 59.877 59.893 59.861 59.814

Extreme Generation Loss

The FR to an extreme event (i.e., loss of three Palo Verde units) compared to that of the designbasis event (i.e., loss of two Palo Verde units) is close to linear, and showed a slight degradation 

due to the larger-sized event and more governor controls saturating. This is reassuring from a 

robustness perspective, though a severe event will still cause UFLS-triggered interruptions, just 

as it does today.

While UFLS action is allowed for a severe event like this extreme generation tripping, cascading 

failure is not. One sensitivity case in which the embedded PV DG was pessimistically assumed 

to have aggressive under-frequency tripping resulted in an acute frequency depression and would 

have likely caused widespread outages.

Distributed vs. Central Station Generation Tripping

System performance in response to a large DG outage was compared to a large central station 

outage, as shown in Figure 13. The system frequency plot shows that the DG event results in a 

less severe frequency nadir and a better settling frequency. The difference is relatively small and 

is primarily due to two factors. First, the loss of locally generated power depresses the load 

voltage and causes the net load to drop. This load relief helps the system frequency. A second 

factor is that the tripped DG is less than the 2,750 MW of the Palo Verde event, due to voltage 

effects on the tripping logic in the composite load model. However, the post-disturbance voltages 

tend to be different, which can have substantial impact on load active power. This result tends to 

reinforce the conclusion that load voltage sensitivity is a more important consideration for FR

than load frequency sensitivity. Broadly, the location of the generation tripping is not as 

important as the amount of generation that is tripped. The mechanisms for widespread DG 

tripping are complex, so it may be possible for more DG to trip than was used in this sensitivity 

case. 
16 

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Figure 13. Frequency response of Light Spring Hi-Mix case – DG trip vs. two Palo Verde unit trip.

System Inertia

Much has been said about the possible impact of loss of system inertia due to the displacement of 

synchronous generation by inverter-based resources. Between the Light Spring Base case and the 

Hi-Mix case, the initial rate of change of frequency (ROCOF) increases about 18%. The impact 

of this increased ROCOF on the system stability is nearly invisible in terms of FR: both the nadir 

and the settling frequency are essentially unchanged. It should be noted that these levels of 

ROCOF, on the order of 0.1 Hz/s, are quite small compared to some of the smaller systems 

around the world that have ROCOF concerns primarily driven by the use of ROCOF relays. This 

reinforces other results that suggest that the loss of system inertia associated with increased wind 

and solar generation is of little consequence for up to at least 50% levels of instantaneous 

penetration for the Western Interconnection as long as adequately fast primary frequency 

responsive resources are maintained.

Headroom Depletion

The effects of headroom depletion due to a relatively rapid afternoon decline in solar PV 

generation—the so-called “duck curve”—is a growing concern. In an effort to bound the 

problem, an extreme case was simulated where all PV generation in the Western Interconnection 

was shut down, mimicking sunset, while no other generation was committed. This does not 

create a catastrophic failure in the system performance for the given commitment and dispatch. 

No dramatic changes in performance were observed (i.e., there was no cliff) as the PV dropped 

Trip of two Palo Verde units

Trip of equivalent DG 
17

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out. Rather, the degradation of FR is steady and monotonic, while transient stability was 

maintained.

However, once the PV output is reduced to zero, the overall WECC FR is marginal, even with 

significant contribution from California hydro. The FR for California is below the approximate 

statewide FRO. To test the impact of having less responsive hydro, governors were removed as a 

proxy for low water levels or other constraints on the hydro generators' ability to provide more 

power. As the California hydro becomes less responsive, the overall WECC FR drops, and 

eventually WECC fails to meet the IFRO.

As PV drops output, the system must be re-dispatched, which creates many local stress points 

(e.g., poor voltage and thermal overloads). This suggests that the need to commit/recommit units 

could be driven as much by local constraints as overall stability. The details will be important as 

the system stress builds. This further suggests that locational issues may drive some constraints 

on how system operators strive to maintain adequate FR.

Means to Improve Frequency Response

Current operating practice uses traditional approaches (e.g., commit conventional plants with 

governors) to meet all FR needs. Selected non-traditional frequency-responsive controls on wind, 

solar PV, CSP plants, and energy storage were examined in this study. 

Frequency-Responsive Controls on Wind Plants

This study examined two types of frequency-responsive controls for wind plants. The Light 

Spring Hi-Mix case was tested with a governor function (or active power control), inertial 

control, and a combination of both. As shown in Figure 14, the inertial control helps improve the 

nadir, but the energy recovery tends to stretch out the frequency depression. A substantial 

improvement in the margin above UFLS is realized. Unlike the governor function, the inertial 

control has no opportunity or lost energy cost. There is, however, a capital cost associated with 

the controls.

The governor or active power control alone greatly improved the settling frequency and the 

frequency response, but had little impact on the nadir. The combination of both the governor and 

inertial control improved the frequency nadir, settling frequency, and frequency response. Note 

that the wind governor controls were set to emulate those on conventional generation. Both the 

wind governor and inertial controls could be made more aggressive, as is examined with the 

utility-scale PV and energy storage controls below.
18

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Figure 14. Frequency response to two Palo Verde unit trip for Light Spring Hi-Mix case with three

combinations of frequency controls on wind plants.

Frequency-Responsive Controls on Utility-Scale Solar PV Plants

Primary FR from utility-scale solar PV generation is effective at improving both nadir and 

settling frequency, as shown in Figure 15. Unlike the governor controls for wind plants, the 

control used here is aggressive: the response is fast, with gains and time constants selected to 

saturate relatively quickly once the system frequency is outside of the dead band. The PV plant 

response to the design-basis event (i.e., loss of two Palo Verde units) is so fast that it is 

essentially a step response. Had the event been somewhat less severe, the control would still 

have saturated and provided a proportionally greater response. Thus, the FR metric would show a 

greater benefit. Conversely, had the event been even larger, the FR metric would be worse. 

Light Spring Hi-Mix

Light Spring Hi-Mix with governor control

Light Spring Hi-Mix with inertial control

Light Spring Hi-Mix with both controls
19 

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Figure 15. Frequency response to two Palo Verde unit trip for Light Spring Hi-Mix – with and 

without governor control on utility-scale PV plants.

Frequency Response from Energy Storage 

This study shows that the WECC-wide FR meets NERC criteria and the system avoids UFLS for 

all cases examined. However, many of the individual areas are short of FR. Note that the FROs

assigned to individual areas in this study are estimates. The NERC rules apply specifically and 

exclusively to individual BAs. There is no requirement that BAs meet their FROs with resources 

within their BAs.

In this investigation, inverter-based energy storage systems are added to areas short of FR. The 

model used for this investigation is deliberately independent of the storage medium (e.g., 

batteries, flywheels, super conducting magnetic energy storage, etc.). It is assumed that the 

medium has sufficient energy to supply the nominal power rating for 60 seconds and that it has 

the dynamic capability necessary to follow the change in power required for the control. The 

storage systems for each area were sized specifically to meet that area's estimated FRO, and an 

aggressive governor control was applied to each system. As shown in Figure 16, primary FR

from fast energy storage is effective at improving both nadir and settling frequency. A total of 

about 400 MW of energy storage for all of the Western Interconnection allowed the individual 

areas that were short of FR to meet their approximate FROs with resources in their areas. The 

NERC requirements allow individual areas to contract with others for sufficient frequencyresponsive resources to meet their obligation.

Light Spring Hi-Mix

Light Spring Hi-Mix with governor controls 

on utility-scale PV plants
20 

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Figure 16. Frequency response to two Palo Verde unit trip for Light Spring Hi-Mix – with and 

without energy storage.

Transient Stability Results

During heavy load conditions, the addition of high levels of wind and solar generation increases 

the heavy loading on the Pacific AC and DC Interties to about their present path ratings. High 

flows on the California Oregon Interface (COI) are well known to be stressful and to require a 

generation-tripping remedial action scheme (RAS). The investigation suggests that this practice 

can continue, and that the transient stability of the system for one of the well-known and critical 

events for the Western Interconnection is not fundamentally changed by the high wind and solar 

generation, as shown in Figure 17. One sensitivity case in which the Base case had the same

Pacific DC Intertie (PDCI) and COI loading had slightly worse performance than the Hi-Mix 

case. This conclusion is not a statement that the system behaves identically. It is possible, and 

perhaps likely, that the system dynamics are sufficiently different to require somewhat different 

levels of generator tripping or different arming criteria. A complete evaluation of the current 

practice to check for refinements would be prudent. There is, however, nothing in this analysis to 

indicate that the system dynamics have fundamentally changed and that radically different means 

to ensure stability for this event are required.

Light Spring Hi-Mix

Light Spring Hi-Mix with energy storage
21

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Figure 17. COI Flows for PDCI event for Heavy Summer cases.

Local Stability 

There are many localized stability limits in the West. The addition of substantial wind and solar 

generation has the potential to alter the system dynamics of the events that dictate these limits.

For the limited examples, the local system stability is slightly better in the Hi-Mix case.

Distributed Generation Fault Ride-Through

The deliberate or sympathetic trip of distributed PV during disturbances results in a slower 

recovery and lower sustained voltages. Local reactive power balance can be disrupted, with 

reactive power demand increasing many times the amount of active power tripped. In one test, 

with a pessimistic approximation to a worst-case under-voltage tripping, the loss of the DG 

causes a system collapse.

A number of cases showed adverse consequences, up to and including system collapse, from 

widespread tripping of embedded PV DG. Consequently, both prudence and existing reliability 

rules would argue against widespread, common-mode DG tripping for moderately severe voltage 

dips or frequency excursions.

Heavy Summer Base 

Heavy Summer Base with high 

COI flows

Heavy Summer Hi-Mix with 

high COI flows
22

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IEEE Standard 1547a, published in May 2014, revises three existing requirements for 

interconnection of DG with electric power systems. It now has significantly wider mandated 

ranges for DG allowable trip settings in response to utility abnormal voltages and frequency,

with different specified settings allowed via mandatory mutual agreement between the power 

system and DG operators. However, when the grid experiences a large disturbance, if the IEEE 

1547 default trip settings are used for all DG sites, then that may result in widespread DG 

tripping at the same time. The draft IEEE Standard 1547.8 further permits additional DG 

functions to support the grid, again via mutual agreement. Although this draft has initially been 

approved by IEEE balloters, it is undergoing final revisions before publication.

The system-wide impact of common-mode tripping of significant amounts of DG, regardless of 

the mechanism, requires more study.

Coal Displacement and Weak Grid in the Northeast Region

A high de-commitment of coal did not overstress the system, but local voltage and thermal 

problems did occur and were addressed with conventional transmission reinforcements. Figure 

18 shows the change in dispatch with increasing wind and solar production in the Desert 

Southwest and Northeast regions for the Light Spring cases. A more than 80% reduction of coal 

commitment in the Northeast region in the Hi-Mix case, compared to the Base case, resulted in 

acceptable dynamic behavior for the limited tests performed. System dynamics were stable for an 

extra-high-voltage fault at Aeolus, in the heart of the high wind area of the Northeast. The 

system non-synchronous penetration (SNSP) was driven to 56% in the Hi-Mix case.

The regional transmission system was designed based on the size and location of the large coal

power plants, which thus became critical nodes in the network. As a result, the transmission 

system operators have historically counted on those plants to provide the voltage and reactive 

power support needed for reliable operation. Displacement of those central plants by more 

dispersed wind and solar generation results in those nodes being poorly supported. Not 

surprisingly, local voltage and thermal problems occur, and good planning practices need to be 

followed.

The de-commitment in the Extreme sensitivity case further stresses the system, with a more than 

90% reduction of coal commitment from the Light Spring Base case. This gives an SNSP of 

about 66%. The rapid voltage collapse and system separation during the fault, as shown by the 

green trace in Figure 19, is representative of so-called “weak grid” issues. Systems with very 

high levels of inverter-based generation are challenged to provide fast, confident control during 

faults and other disturbances. No commercially available wind or utility-scale solar PV 

generation is capable of operation in a system without the stabilizing benefit of synchronous 

machines. Therefore, the conversion of some coal plants to synchronous condensers and the 

addition of mechanically switched shunt compensation were needed to stabilize the Aeolus fault 

with the conservative load and wind plant modeling used. The synchronous condenser

conversion (assuming retirement) works well to stabilize the system, as shown in Figure 19. The 

system recovers in an orderly fashion when the fault is cleared. The synchronous condenser 

conversion improves the SNSP from about 66% to 61%.
23

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Figure 18. Coal displacement in Desert Southwest and Northeast regions for Light Spring cases.

Figure 19. Dave Johnson bus voltage for Aeolus fault – Light Spring Base vs. Hi-Mix vs. Extreme 

vs. Extreme with synchronous condenser conversion.

0

5000

10000

15000

20000

25000

30000

35000

LSP Base LSP HiMix LSP HiMixXtrm LSP Base LSP HiMix LSP HiMixXtrm

DSW NorthEast

WIND

Steam

PV

PSH

Other

NUC

HYDRO

GEO

GasCT

CSP

Coal

CCPP

Bio

Light Spring Base

Light Spring Hi-Mix 

Light Spring Extreme

Light Spring Extreme 

with synchronous 

condenser conversion
24 

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Means to Improve Transient Stability

Transmission Additions

The mitigation investigation in WWSIS-3 included a portion of the WWSIS-2 transmission 

additions to examine their impact on the transient stability of the COI. The added transmission 

stabilizes the system without a generation-tripping RAS. This reinforces the need to analyze 

whether the interface limits should change. 

Frequency-Responsive Controls on CSP Plants

The CSP plants are modeled as base load steam plants under most conditions. However, the 

potential contribution of CSP steam turbines to FR was examined by enabling GR on all the new 

CSP plants.

The PDCI event can cause system separation at the COI unless some RAS generation tripping is 

enabled. Figure 20 shows a potential benefit from having CSP GR. In this case, the PDCI event 

is imposed with the CSP GR enabled. The figure shows that the system is stabilized without 

resorting to a RAS. This is because the beneficial contribution of CSP is geographically 

advantageous for this event. Most of the CSP is to the south of the COI, so the transient increase 

in power output from these plants is such that power swing from north to south on the COI is 

slightly reduced and eliminates the voltage collapse along the corridor. Thus, the beneficial CSP 

contribution to FR also has a positive locational aspect that benefits transient stability. 

Figure 20. Malin station bus voltage in response to PDCI event – with and without CSP governor 

control. 

Heavy Summer Hi-Mix (no RAS)

Heavy Summer Hi-Mix with CSP 

governor control (no RAS)
25 

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Model Improvement and Further Analysis

Load Model 

Changing the load model had a greater impact on system performance than did changing the 

level of renewable generation. The results of a three-phase fault at Vincent 500 kV in California 

for the Heavy Summer Original and Base cases are shown in Figure 21. The Original case uses 

the standard WECC load model, and the Base case uses the composite load model. The behavior 

of the system for deep faults is completely dominated by the load model, and more specifically 

by the tripping vs. stalling behavior assumed for the motor constituents of the composite load. 

The motor stalling behavior is exacerbated by blocking or tripping of embedded PV. This is an 

extraordinarily complex issue for planning and for research. This stability risk is not primarily 

one of utility-scale renewable integration. 

Figure 21. Load-induced voltage collapse in Heavy Summer Base case.

Heavy Summer with standard load model

Heavy Summer with composite load 

model
26

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Wind and Solar Models 

When wind and solar are the dominant source of generation throughout the region, it will be 

important to have appropriate dynamic models. WECC has a longstanding best practice to keep 

dynamic models up to date. Wind and solar plant models need to be held to the same level of 

accuracy in a high-penetration future. Adoption of wind plant controls designed for weak grids 

greatly improved system stability. Further, the results were extremely sensitive to the 

assumptions about load modeling, as described above.

Frequency-Responsive Control Philosophy 

The combined findings of the wind, solar, and energy storage investigations suggest that the best 

use of rapidly responding power-electronics-enabled resources for FR is non-linear. The 

medium—wind or solar or energy storage or a combination—is less important than the control 

philosophy employed. Other technologies that deliver similar dynamic response, such as fast 

control of loads, would likely produce similar improvements. 

In the past, the primary control variable was gain, in the form of governor droop, and speed of 

response was not readily adjusted. Coordinating droops and ensuring adequate response were 

more straightforward. With the added flexibility of easily adjustable speed of response, and the 

necessity to consider energy as well as power constraints, the frequency control problem also 

gains complexity. With the addition of non-linear frequency-responsive resources, practice will 

need to evolve and incorporate FR that is a function of the size of the disturbing event. As in the 

past, locational aspects may prove important in some cases.

Path Rating Analyses

The majority of the results presented in this study used the transmission topology directly from 

the WECC planning databases. These WECC cases included significant new transmission that is 

not currently in service. With the exception of some local patches, no further major 

reinforcements were added. In general, WWSIS-3 did not identify dramatic changes in system 

dynamics. However, the large changes in system flow patterns suggest that a rigorous analysis of 

individual paths is needed to ensure reliability. Certainly, all the regional paths in the high wind 

parts of the Northeast region will change as transmission is added to accommodate the new 

plants. A complete system evaluation is needed to assess the impact of a major transmission 

change like this on path limits.

Coal Displacement Analysis

The sequence of coal displacement sensitivities in this study is illuminating, but in no way 

complete or conclusive. It provides an opportunity to investigate the transient stability 

implications of not only temporary de-commitment of coal generation, but also the impact of 

possible coal plant retirements. The key point is that transient stability analysis is always based 

on snapshots of operation. From a system dynamics perspective, whether a specific generating 

resource is off-line because it was de-committed for a particular operating condition is 

indistinguishable from a permanent retirement. The displacement by wind and solar was based 

on the economic analysis of WWSIS-2 rather than an arbitrary, plant-by-plant choice. 

The system appears to behave well for the Hi-Mix case when almost all the large coal plants in 

the eastern regions are off-line. However, displacing even more coal units and pushing SNSP 
27

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above 60% appears to cause problems. This small sample suggests that care must be exercised in 

driving the system from a high level of coal displacement to an extreme level of coal 

displacement. More analysis is needed.

Conclusions

WWSIS-3 did not identify any fundamental reasons why the Western Interconnection cannot 

meet transient stability and FR objectives with high levels of wind and solar generation. 

However, good system planning and power system engineering practices must be followed. At a 

minimum, local voltage and thermal problems will inevitably require some transmission system 

improvements. The dynamic behavior of distributed PV generation was shown to have the 

potential to substantially impact the bulk power system. Distribution is not decoupled from 

transmission, and it will impact bulk power system operation. Mechanisms are needed to allow 

BAs to both share frequency-responsive resources and make sure that they have adequate 

frequency-responsive resources within their control. From a transient stability perspective, the 

system appears to tolerate substantial displacement of thermal generation. However, care will be 

needed in the event that the system, especially in the Desert Southwest and Northeast regions, is

driven to near-zero commitment of coal plants. Note that this investigation is not a substitute for 

thorough system planning studies. The study conclusions are provided in bullet format below.

Transient Stability Conclusions

For the conditions studied:

• System-wide transient stability can be maintained with high levels of wind and solar 

generation if local stability, voltage, and thermal problems are addressed with traditional 

transmission system reinforcements (e.g., transformers, shunt capacitors, local lines).

With these reinforcements, an 80% reduction in coal plant commitment, which drove 

SNSP to 56%, resulted in acceptable transient stability performance.

• With further reinforcements, including non-standard items such as synchronous 

condenser conversions, a 90% reduction in coal plant commitment, which drove SNSP to 

61%, resulted in acceptable transient stability performance. 

• Additional transmission and CSP generation with frequency-responsive controls are 

effective at improving transient stability.

Frequency Response Conclusions

For the conditions studied:

• System-wide FR can be maintained with high levels of wind and solar generation if local 

stability, voltage, and thermal problems are addressed with traditional transmission 

system reinforcements (e.g., transformers, shunt capacitors, local lines). 

• Limited application of non-traditional frequency-responsive controls on wind, solar PV, 

CSP plants, and energy storage are effective at improving both frequency nadir and 

settling frequency, and thus FR. Refinements to these controls would further improve 

performance.
28

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• Individual BA FR may not meet its obligation without additional FR from resources both 

inside and outside the particular area. As noted above, non-traditional approaches are 

effective at improving FR. Current operating practice uses more traditional approaches 

(e.g., committing conventional plants with governors) to meet all FR needs. 

• Using new, fast-responding resource technologies (e.g., inverter-based controls) to ensure 

adequate FR adds complexity, but also flexibility, with high levels of wind and solar 

generation. Control philosophy will need to evolve to take full advantage of easily 

adjustable speed of response, with additional consideration of the location and size of the 

generation trip. 

• For California, adequate FR was maintained during acute depletion of headroom from 

afternoon drop in solar production, assuming the ability of California hydro to provide 

FR.

Other Conclusions

• Accurate modeling of solar PV, CSP, wind, and load behavior is extremely important 

when analyzing high-stress conditions, as all of these models had an impact on system 

performance. 

• Attention to detail is important. Local and locational issues may drive constraints on both 

FR and transient stability.

• The location of generation tripping, e.g., DG vs. central station, is not as important as the 

amount of generation that is tripped. However, widespread deliberate or common-mode 

DG tripping after a large disturbance has an adverse impact on system performance. It is 

recommended that practice adapt to take advantage of new provisions in IEEE 1547 that

allow for voltage and frequency ride-through of DG to improve system stability.

• Further analysis is needed to determine operational limits with low levels of synchronous 

generation in order to identify changes to path ratings and associated remedial action 

schemes, as well as quantify the impact of DG on transmission system performance.

• Because a broad range of both conventional and non-standard operation and control 

options improved system performance, further investigation of the most economic and 

effective alternatives is warranted. This should include consideration of the costs and 

benefits of constraining commitment and dispatch to reserve FR, as well as the capital 

and operating costs of new controls and equipment.

References

Kundur, P., et al. (2004). "Definition and Classification of Power System Stability." IEEE 

Transactions on Power Systems. Vol. 19, No. 2; pp. 1387-1401.

NERC (2012). Standard BAL-003 Frequency Response and Frequency Bias Setting. 

Vittal, V. (2003). "Transient Stability and Control of Large Scale Power Systems." Power 

Systems Engineering Research Center Background Paper.